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Summary of significant accounting policies | 12 Months Ended
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Dec. 31, 2013
Accounting Policies [Abstract] |
Summary of significant accounting policies | Summary of Significant Accounting Policies Basis of presentation The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, pipeline and energy services, exploration and production, construction materials and contracting, construction services and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Exploration and production, construction materials and contracting, construction services and other are nonregulated. For further descriptions of the Company's businesses, see Note 15. Intercompany balances and transactions have been eliminated in consolidation, except for certain transactions related to the Company's regulated operations in accordance with GAAP. The statements also include the ownership interests in the assets, liabilities and expenses of jointly owned electric generating facilities. The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses. The Company's regulated businesses account for certain income and expense items under the provisions of regulatory accounting, which requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after December 31, 2013, up to the date of issuance of these consolidated financial statements. Cash and cash equivalents The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Accounts receivable and allowance for doubtful accounts Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. For more information, see Percentage-of-completion method in this note. The total balance of receivables past due 90 days or more was $36.4 million and $34.3 million as of December 31, 2013 and 2012, respectively. The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts as of December 31, 2013 and 2012, was $10.1 million and $10.8 million, respectively. Inventories and natural gas in storage Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories at December 31 consisted of:
| 2013 |  | 2012 |
| (In thousands)
Aggregates held for resale | $ | 101,568 |  | $ | 87,715 |
Materials and supplies | 69,808 |  | 69,390 |
Asphalt oil | 38,099 |  | 67,480 |
Merchandise for resale | 21,720 |  | 31,172 |
Natural gas in storage (current) | 16,417 |  | 29,030 |
Other | 34,779 |  | 32,628 |
Total | $ | 282,391 |  | $ | 317,415 |
The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $48.3 million and $49.7 million at December 31, 2013 and 2012, respectively. Investments The Company's investments include its equity method and cost method investments as discussed in Note 4, the cash surrender value of life insurance policies, an insurance contract, mortgage-backed securities and U.S. Treasury securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company measures its investment in the insurance contract at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. The Company has not elected the fair value option for its mortgage-backed securities and U.S. Treasury securities and, as a result, the unrealized gains and losses on these investments are recorded in accumulated other comprehensive income (loss). For more information, see Notes 8 and 16. Property, plant and equipment Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for exploration and production properties as described in Oil and natural gas properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, at the exploration and production segment only on costs that have been excluded from the full cost amortization pool and on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized for the years ended December 31 were as follows:
| 2013 |  | 2012 |  | 2011 |
| (In thousands)
Interest capitalized | $ | 6,033 |  | $ | 8,659 |  | $ | 10,821 |
AFUDC - borrowed | $ | 2,767 |  | $ | 2,483 |  | $ | 1,666 |
AFUDC - equity | $ | 3,322 |  | $ | 4,530 |  | $ | 2,587 |
Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and exploration and production properties, which are amortized on the units-of-production method based on total proved reserves. The Company collects removal costs for plant assets in regulated utility rates. These amounts are recorded as regulatory liabilities, which are included in other liabilities. Property, plant and equipment at December 31 was as follows:
| 2013 |  | 2012 |  | Weighted Average Depreciable Life in Years
| (Dollars in thousands, where applicable)
Regulated: |  |  |
Electric: |  |  |
Generation | $ | 570,394 |  | $ | 546,011 |  | 42
Distribution | 308,202 |  | 276,446 |  | 39
Transmission | 196,824 |  | 180,543 |  | 48
Construction in progress | 141,365 |  | 62,123 |  | -
Other | 99,037 |  | 85,461 |  | 14
Natural gas distribution: |  |  |  |  |
Distribution | 1,384,587 |  | 1,308,314 |  | 40
Construction in progress | 46,763 |  | 71,679 |  | -
Other | 345,551 |  | 309,957 |  | 25
Pipeline and energy services: |  |  |  |  |
Transmission | 418,594 |  | 403,126 |  | 52
Gathering | 39,597 |  | 42,420 |  | 19
Storage | 42,939 |  | 42,058 |  | 51
Construction in progress | 6,937 |  | 13,667 |  | -
Other | 39,504 |  | 38,386 |  | 29
Nonregulated: |  |  |  |  |
Pipeline and energy services: |  |  |  |  |
Midstream | 213,063 |  | 233,840 |  | 17
Construction in progress | 188,641 |  | 29,657 |  | -
Other | 12,897 |  | 13,379 |  | 11
Exploration and production: |  |  |  |  |
Oil and natural gas properties | 3,017,879 |  | 2,723,356 |  | *
Other | 42,969 |  | 41,204 |  | 8
Construction materials and contracting: |  |  |  |  |
Land | 125,551 |  | 126,788 |  | -
Buildings and improvements | 70,000 |  | 73,884 |  | 19
Machinery, vehicles and equipment | 906,774 |  | 899,592 |  | 12
Construction in progress | 13,315 |  | 11,165 |  | -
Aggregate reserves | 394,715 |  | 393,552 |  | **
Construction services: |  |  |  |  |
Land | 4,821 |  | 4,723 |  | -
Buildings and improvements | 16,628 |  | 16,563 |  | 20
Machinery, vehicles and equipment | 105,991 |  | 100,445 |  | 6
Other | 7,508 |  | 8,893 |  | 4
Other: |  |  |  |  |
Land | 2,837 |  | 2,837 |  | -
Other | 47,160 |  | 47,682 |  | 23
Eliminations | (7,177 | ) | — |  |
Less accumulated depreciation, depletion and amortization | 3,872,487 |  | 3,608,912 |  |
Net property, plant and equipment | $ | 4,931,379 |  | $ | 4,498,839 |  |
* Amortized on the units-of-production method based on total proved reserves at a BOE average rate of $17.41, $15.28 and $12.25 for the years ended December 31, 2013, 2012 and 2011, respectively. Includes oil and natural gas properties accounted for under the full-cost method, of which $124.9 million and $191.8 million were excluded from amortization at December 31, 2013 and 2012, respectively. ** Depleted on the units-of-production method. Impairment of long-lived assets The Company reviews the carrying values of its long-lived assets, excluding goodwill and oil and natural gas properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In 2013 and 2012, the Company recognized impairments of $9.0 million (after tax) and $1.7 million (after tax), respectively, which are recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairments are related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 8. No significant impairment losses were recorded in 2011. Unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date. Goodwill Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired. The goodwill impairment test is a two-step process performed at the reporting unit level. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. For more information on the Company's operating segments, see Note 15. The first step of the impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit's goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. For the years ended December 31, 2013, 2012 and 2011, there were no impairment losses recorded. At December 31, 2013, the fair value substantially exceeded the carrying value at all reporting units. Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the Company's future revenue, profitability and cash flows, amount and timing of estimated capital expenditures, inflation rates, weighted average cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is determined using a weighted combination of income and market approaches. The Company uses a discounted cash flow methodology for its income approach. Under the income approach, the discounted cash flow model determines fair value based on the present value of projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are discounted using a rate which reflects the best estimate of the weighted average cost of capital at each reporting unit. The weighted average cost of capital, which varies by reporting unit and is in the range of 5 percent to 10 percent, and a long-term growth rate projection of approximately 3 percent were utilized in the goodwill impairment test performed in the fourth quarter of 2013. Under the market approach, the Company estimates fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, the Company adds a reasonable control premium when calculating the fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants. The Company believes that the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Oil and natural gas properties The Company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized. Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes. At December 31, 2013, the Company's full-cost ceiling exceeded the Company's capitalized cost. However, there is risk that lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in additional future noncash write-downs of the Company's oil and natural gas properties. The Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at September 30, 2012 and December 31, 2012. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. SEC Defined Prices as of September 30, 2012 and December 31, 2012, were $94.97 per Bbl for NYMEX oil and $2.83 per MMBtu for Henry Hub natural gas and $94.71 per Bbl for NYMEX oil and $2.76 per MMBtu for Henry Hub natural gas, respectively. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-downs amounted to $160.1 million and $231.7 million ($100.9 million and $145.9 million after tax) for the three months ended September 30, 2012 and December 31, 2012, respectively. The Company hedged a portion of its oil and natural gas production and the effects of the cash flow hedges were used in determining the full-cost ceiling at September 30, 2012 and December 31, 2012. The Company would have recognized additional write-downs of its oil and natural gas properties of $19.5 million ($12.3 million after tax) at September 30, 2012, and $20.8 million ($13.1 million after tax) at December 31, 2012, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7. The following table summarizes the Company's oil and natural gas properties not subject to amortization at December 31, 2013, in total and by the year in which such costs were incurred:
|  | Year Costs Incurred
| Total |  | 2013 |  | 2012 |  | 2011 |  | 2010 and prior |
| (In thousands)
Acquisition | $ | 93,758 |  | $ | 1,514 |  | $ | 23,588 |  | $ | 28,543 |  | $ | 40,113 |
Development | 14,824 |  | 12,622 |  | 1,633 |  | 271 |  | 298 |
Exploration | 14,547 |  | 9,952 |  | 4,346 |  | 198 |  | 51 |
Capitalized interest | 1,740 |  | 340 |  | 418 |  | 410 |  | 572 |
Total costs not subject to amortization | $ | 124,869 |  | $ | 24,428 |  | $ | 29,985 |  | $ | 29,422 |  | $ | 41,034 |
Costs not subject to amortization as of December 31, 2013, consisted primarily of unevaluated leaseholds and development costs in the Bakken area, Texas properties and the Paradox Basin. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed. Revenue recognition Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $107.4 million and $85.9 million at December 31, 2013 and 2012, respectively. The Company recognizes construction contract revenue at its construction businesses using the percentage-of-completion method as discussed later. The Company recognizes revenue from exploration and production properties only on that portion of production sold and allocable to the Company's ownership interest in the related properties. The Company recognizes all other revenues when services are rendered or goods are delivered. The Company presents revenues net of taxes collected from customers at the time of sale to be remitted to governmental authorities, including sales and use taxes. Percentage-of-completion method The Company recognizes construction contract revenue from fixed-price and modified fixed-price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. If a loss is anticipated on a contract, the loss is immediately recognized. Costs and estimated earnings in excess of billings on uncompleted contracts represent revenues recognized in excess of amounts billed and were included in receivables, net. Billings in excess of costs and estimated earnings on uncompleted contracts represent billings in excess of revenues recognized and were included in accounts payable. Costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings on uncompleted contracts at December 31, were as follows:
| 2013 |  | 2012 |
| (In thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts | $ | 60,828 |  | $ | 64,996 |
Billings in excess of costs and estimated earnings on uncompleted contracts | $ | 84,189 |  | $ | 83,167 |
Amounts representing balances billed but not paid by customers under retainage provisions in contracts at December 31, were as follows:
| 2013 |  | 2012 |
| (In thousands)
Short-term retainage * | $ | 55,906 |  | $ | 54,256 |
Long-term retainage ** | 4,229 |  | 2,038 |
Total retainage | $ | 60,135 |  | $ | 56,294 |
* Expected to be paid within one year or less and included in receivables, net. ** Included in deferred charges and other assets - other. Derivative instruments The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties. The Company's policy generally allows the hedging of monthly forecasted sales of oil and natural gas production at Fidelity for a period up to 42 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. The Company's policy allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years. The Company's policy requires that each month as physical oil and natural gas production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month's production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month's physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value. The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12-month period. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7. The Company's derivative instruments are reflected at fair value. For more information, see Note 8. Asset retirement obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 10. Legal costs The Company expenses external legal fees as they are incurred. Natural gas costs recoverable or refundable through rate adjustments Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $16.9 million and $35.3 million at December 31, 2013 and 2012, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $12.1 million and $3.0 million at December 31, 2013 and 2012, respectively, which is included in prepayments and other current assets. Insurance Certain subsidiaries of the Company are insured for workers' compensation losses, subject to deductibles ranging up to $1 million per occurrence. Automobile liability and general liability losses are insured, subject to deductibles ranging up to $1 million per accident or occurrence. These subsidiaries have excess coverage above the primary automobile and general liability policies on a claims first-made and reported basis beyond the deductible levels. The subsidiaries of the Company are retaining losses up to the deductible amounts accrued on the basis of estimates of liability for claims incurred and for claims incurred but not reported. Income taxes The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures. The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on regulated electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions. Tax positions taken or expected to be taken in an income tax return are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes. Foreign currency translation adjustment The functional currency of the Company's investment in ECTE, as discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using an average of the daily exchange rates. Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income. Earnings (loss) per common share Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options and performance share awards. In 2013 and 2011, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the year ended December 31, 2012, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the year. Due to the loss on common stock for the year ended December 31, 2012, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculation was as follows:
| 2013 |  | 2012 |  | 2011 |
| (In thousands)
Weighted average common shares outstanding - basic | 188,855 |  | 188,826 |  | 188,763 |
Effect of dilutive stock options and performance share awards | 838 |  | — |  | 142 |
Weighted average common shares outstanding - diluted | 189,693 |  | 188,826 |  | 188,905 |
Shares excluded from the calculation of diluted earnings per share | — |  | 58 |  | — |
Use of estimates The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and oil and natural gas properties; fair values of acquired assets and liabilities under the acquisition method of accounting; oil, NGL and natural gas proved reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Cash flow information Cash expenditures for interest and income taxes for the years ended December 31 were as follows:
| 2013 |  | 2012 |  | 2011 |
| (In thousands)
Interest, net of amount capitalized | $ | 81,689 |  | $ | 74,378 |  | $ | 78,133 |
Income taxes paid (refunded), net | $ | 24,857 |  | $ | 3,277 |  | $ | (12,287 | )
Noncash investing transactions at December 31 were as follows:
| 2013 |  | 2012 |  | 2011 |
| (In thousands)
Property, plant and equipment additions in accounts payable | $ | 67,129 |  | $ | 76,205 |  | $ | 41,540 |
New accounting standards Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income In February 2013, the FASB issued guidance on the reporting of amounts reclassified out of accumulated other comprehensive income. This guidance requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. Entities may present this information either on the face of the statement where net income is presented or in the notes. This guidance was effective for the Company on January 1, 2013, and is to be applied prospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows. Disclosures about Offsetting Assets and Liabilities In December 2011, the FASB issued guidance on the disclosure requirements related to balance sheet offsetting. The new disclosure requirements relate to the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. In January 2013, the FASB issued guidance clarifying the scope of the disclosures related to balance sheet offsetting. The amendments clarify that this guidance only applies to derivative instruments, repurchase agreements and securities lending transactions that are either offset or subject to an enforceable master netting arrangement. The guidance was effective for the Company on January 1, 2013, and must be applied retrospectively. The guidance required additional disclosures, however it did not impact the Company's results of operations, financial position or cash flows. Variable interest entities The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Comprehensive income (loss) Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, postretirement liability adjustments, foreign currency translation adjustments and gains (losses) on available-for-sale investments. For more information on derivative instruments, see Note 7. The after-tax changes in the components of accumulated other comprehensive loss as of December 31, 2013, 2012 and 2011, were as follows:
| Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges |  | Postretirement Liability Adjustment |  | Foreign Currency Translation Adjustment |  | Net Unrealized Gains on Available-for-sale Investments |  | Total Accumulated Other Comprehensive Loss |
| (In thousands)
Balance at December 31, 2011 | $ | 6,275 |  | $ | (53,320 | ) | $ | (38 | ) | $ | 82 |  | $ | (47,001 | )
Current-period other comprehensive income (loss) | (257 | ) | (1,027 | ) | (473 | ) | 37 |  | (1,720 | )
Balance at December 31, 2012 | 6,018 |  | (54,347 | ) | (511 | ) | 119 |  | (48,721 | )
Other comprehensive income (loss) before reclassifications | (5,594 | ) | 18,539 |  | (299 | ) | (194 | ) | 12,452 |
Amounts reclassified from accumulated other comprehensive loss | (4,189 | ) | 2,001 |  | 143 |  | 109 |  | (1,936 | )
Net current-period other comprehensive income (loss) | (9,783 | ) | 20,540 |  | (156 | ) | (85 | ) | 10,516 |
Balance at December 31, 2013 | $ | (3,765 | ) | $ | (33,807 | ) | $ | (667 | ) | $ | 34 |  | $ | (38,205 | )
Reclassifications out of accumulated other comprehensive loss for the year ended December 31 were as follows:
| 2013 |  | Location on Consolidated Statements of Income
| (In thousands) |
Reclassification adjustment for gain (loss) on derivative instruments included in net income: |  |
Commodity derivative instruments | $ | 7,803 |  | Operating revenues
Interest rate derivative instruments | (1,066 | ) | Interest expense
| 6,737 |  |
| (2,548 | ) | Income taxes
| 4,189 |  |
Amortization of postretirement liability losses included in net periodic benefit cost | (3,277 | ) | (a)
| 1,276 |  | Income taxes
| (2,001 | ) |
Reclassification adjustment for loss on foreign currency translation adjustment included in net income | (213 | ) | Earnings (loss) from equity method investments
| 70 |  | Earnings (loss) from equity method investments
| (143 | ) |
Reclassification adjustment for loss on available-for-sale investments included in net income | (168 | ) | Other income
| 59 |  | Income taxes
| (109 | ) |
Total reclassifications | $ | 1,936 |  |
(a) Included in net periodic benefit cost (credit). For more information, see Note 16.

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